From the Table: Extended Laterals

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Welcome to Energy Crew Podcast.
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I'm your host, JP Warren.
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I got something excited kind of that we're doing.
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This is a new project, a new direction, just kind of a new way to get information out there to you, the listeners.
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One of the things that I do, I host these uh operator roundtables, and these are kind of candid strategic conversations in a room full of primarily operators, 70% decision maker, manager level, or above, and select service providers.
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And what we do, we host these round table conversations that we discuss industry challenges, where the industry is going, and various other topics.
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And pretty much what we do, we record every single one.
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And I was thinking, how do we actually share, showcase this information and disseminate it throughout our listeners, throughout our audience?
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And the perfect way is through AI, through all these tools out there, I'm able to upload the transcripts from these round tables and it actually come out and spit out a podcast.
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So actually, if you can't attend the table, you understand what we're talking about.
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So this is just another tool to under to talk to understand what operators are talking about, what challenges are in their mind, and how we're actually moving forward as an industry.
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This first episode I have for you, if you're not, if you're listening to the first episode, I just released a quarterly industry pulse, which we took about 10 transcripts and kind of pumped out a podcast.
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And this one, we're doing a round table specific.
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And this actually took place in Oklahoma City with Jeremy Ents, who was over at Ascent, who was over at Flywheel Now, led a conversation on extended laterals for drilling.
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How far could we go and how far should we go?
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And it was a packed round table.
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I think we had 22 or 24 people at the table diving in to extended laterals, and it was a great conversation.
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And I took that transcript, uploaded it, and we now have a podcast, and that's what you're about to listen to.
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So um I hope you enjoy.
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Let me know what you think.
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And uh thanks for tuning in to Energy Crew Podcast.
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I mean, just imagine sitting in an office chair, uh a joystick in your hand, and you are steering a drill bit through solid rock.
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Right.
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Literally crushing rock miles away.
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Exactly.
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Now that drill bit is five miles away from you, completely horizontal underground.
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That is roughly the distance from, you know, a downtown office building to your local airport.
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Yeah, it's an insane distance to even conceptualize.
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And you are doing this entirely blindfolded, just relying on sensor data.
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Plus, you have to keep that spinning bit within a perfectly straight, like 10-foot window.
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Right, because if you veer outside of it, you lose millions.
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Yeah, millions of dollars.
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Welcome to the deep dive, everyone.
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Today we are bringing you inside a closed-door roundtable discussion featuring senior drilling and completions engineers from some of the top operators.
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Aaron Powell And we really want to be clear right out of the gate here this isn't some polished corporate PR brochure.
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No, definitely not.
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This is a raw, very grounded look at extreme extended laterals.
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We're going to explore not just how far they can push that bit, but the intense operational realities of why they are doing it.
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And the million-dollar stakes when things go wrong in the dark, which uh happens more than people like to admit.
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Okay, let's unpack this because the definition of what actually constitutes an extreme well seems to have completely changed almost overnight.
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Aaron Powell What's fascinating here is how quickly the extreme has become routine.
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I mean, look at the industry just five years ago.
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Right, a three-mile lateral was a huge deal.
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Exactly.
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Drilling a three-mile lateral, so about 15,000 feet horizontally was considered incredibly sporty.
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It raised eyebrows, it was a massive operational risk.
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And now.
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Today, the average wells these engineers are discussing are over 16,000 feet.
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And the real envelope pushers, they are going far beyond that.
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Yeah, looking at the notes, some operators are pushing past 34,000 feet in total measured depth.
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We are talking over six miles of steel pipe rotating in the earth.
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It's wild.
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It really is.
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But to understand why they are pushing six miles of pipe into the earth, you first have to understand the financial engine driving this kind of extreme engineering.
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Right.
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Because drilling five miles horizontally isn't a vanity project.
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They aren't doing it for a plaque on the wall.
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No, it all comes down to the brutal economics of the surface.
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Spot on.
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The primary driver here is amortizing fixed costs.
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When an operator drills a well, they have to acquire a surface location, build a heavy-duty pad, and drill the vertical drop.
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Just to reach the target reservoir, yeah.
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Exactly.
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And that vertical section plus that surface pad costs the exact same whether the subsequent horizontal lateral is one mile long or five miles long.
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I came up with an analogy to visualize the math here while I was prepping for this.
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Think of it like paying a massive, incredibly expensive toll to get your car onto a restricted highway.
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Okay.
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I like that.
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The vertical drill is the toll.
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Right.
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The toll is the vertical drill and the surface pad.
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Once you have paid that massive toll, you want to drive as many miles as physically possible on that single ticket to get your money's worth.
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You definitely don't want to take the first exit.
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Exactly.
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If you get off the first exit, your cost per mile is just astronomical.
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You want to drive to the end of the state.
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And the toll itself is getting exponentially more expensive, which really forces the issue.
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Take the Northeast, specifically Ohio, for example.
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Oh yeah.
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The roundtable engineers had a lot to say about Ohio.
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They noted that finding surface locations in the Marcellus and Utica is incredibly difficult and shockingly expensive due to population density and topography.
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The surface damages alone are insane.
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The money operators have to pay landowners just to disrupt the surface, can easily run over six figures.
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Right, or top$20,000 a week.
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A week.
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Yeah.
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So saving yourself from having to permit, lease, and build an entirely new vertical well and surface pad by simply drilling a 5,000 foot longer horizontal hole from your existing pad.
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It saves an absolute fortune in upfront capital.
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But there is a calculated trade-off, though, right?
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The roundtable notes that operators actually lose a bit of recovery efficiency at the far end of these megawells.
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Aaron Powell They do.
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They mentioned about a 5% drop in recovery per foot at the toe of the well.
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So the very end of the pipe.
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Right.
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The physics of drawing oil and gas from five miles away dictates that your pressure drawdown just won't be perfectly uniform.
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The heel of the, well, the part closest to the vertical drop will produce more efficiently than the toe.
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Aaron Powell But they do it anyway because it's a brilliant operational compromise.
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Exactly.
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That 5% loss in reservoir recovery at the toe is completely eclipsed by the massive savings in capital efficiency on the surface.
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Because avoiding the cost of a whole new surface pad completely validates sacrificing a tiny fraction of recovery at the absolute end of the lateral.
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The economics are so undeniable that it has actually become a major catalyst for mergers and acquisitions across multiple basins right now.
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Aaron Powell Wait, if it's just a matter of drilling further to improve the economics, why are companies selling their assets?
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Why don't the original owners just hire better rigs and drill the longer laterals themselves?
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Aaron Powell Well, because executing a four or five mile lateral isn't just about renting a bigger rig.
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It requires a massive integration of proprietary engineering IP, customized MUD programs, highly specialized telemetry.
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And massive capital reserves to absorb the risk.
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Exactly.
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So you have operators looking at a competitor's portfolio of tier two, two-mile inventory.
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The original owner just lacks the technical capability and the balance sheet to push those wells further.
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So the acquiring company buys those assets specifically because their proprietary engineering allows them to turn those two mile wells into three or four mile wells.
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You got it.
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It instantly transforms marginal acreage into highly profitable tier one inventory without the original owner ever realizing the potential they were sitting on.
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Here's where it gets really interesting.
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Because if longer laterals fundamentally rewrite the profitability of a basin, why isn't every operator in the country just automatically drilling five-mile wells everywhere?
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Trevor Burrus, Jr.
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Right.
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It seems like a no-brainer.
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But the answer, according to the round table, is that the subsurface physics completely changed depending on your zip code.
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Aaron Powell The Earth is not a uniform factory floor.
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No, not at all.
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You have to look at regional geological differences to understand the operational nightmares these engineers face.
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Aaron Powell Let's start with the Northeast, places like the Marcellus and Utica shales.
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Yeah, the engineers describe this as a highly forgiving, relatively flat and benign geological environment.
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The rock layers are straightforward, with inclination angles usually sitting comfortably between 88 and 92 degrees.
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Aaron Powell It's basically a flat layer cake.
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So in that environment, physics isn't the primary limitation.
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Aaron Powell Far from it.
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In the Northeast, they can push past 20,000 feet with relative ease.
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Their biggest hurdle is almost entirely above ground.
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Land and leasing, right?
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Exactly.
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It's the legal and political nightmare of stitching enough individual property units together to legally drill a five-mile line underground without crossing a boundary they haven't leased.
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Aaron Powell But then you transition down to the mid-continent, Oklahoma, the scoop, the stack, and the tone of the roundtable completely shifts.
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Aaron Powell Oh, completely.
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The mid-continent sounds like an absolute drilling nightmare compared to Ohio.
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Yeah, in the mid-continent, operators are dealing with massive geological faults, unpredictable stress regimes, and major inclination changes.
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The rock actively pushes the bit around, forcing angles up to 95 degrees.
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And this volatile geology introduces the absolute biggest operational enemy of the extended lateral.
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Tortuosity.
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Yes.
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Tortuosity.
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So how does a tiny, say, 15-foot deviation at the very top of the well completely ruin a drilling operation four miles later?
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Well, we have to look at the mechanics of well bore friction.
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If you have ever wrapped a rope around a tree trunk to hold a heavy load, you are familiar with the capstan effect.
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Yeah, like tying off a boat on a dock.
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Exactly.
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Just one or two wraps of that rope create so much exponential friction that you can hold a massive boat in place with one hand.
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Tortuosity in a well bore acts the exact same way.
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So if the rig drifts 15 feet off the line early in the drill path, the steering tools can easily correct back to the center line.
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But they have just created a micro S curve.
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Right.
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A little kink in the pipe.
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And every single piece of steel that follows has to drag through that S curve.
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Yeah.
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And friction in a well bore is exponential, not linear.
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By the time you are trying to push your drill string, your wire line, or your casing three or four miles down the hole, that tiny kink at the top is gripping the pipe with immense force.
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Just like the rope around the tree.
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Exactly.
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The torque and drag become so massive that wire lines will stretch and snap.
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Casing simply cannot be pushed down to the bottom because the sheer compressive force required exceeds the yield strength of the steel.
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It just crushes under its own weight.
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The engineers explicitly noted that if they hand a 14,000 foot well plan to a rig and the rig drifts 15 feet off the line, they just let the directional drillers correct it.
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But if it's a 24,000-foot well plan, they explicitly tell the drillers do not overcorrect.
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Right.
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They say do not put an S curve in this hole early on, or we will never reach the finish line.
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And because of this exponential friction, the standard industry friction models the predictive software that engineers have relied on for decades, completely break down at these extreme lengths.
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The physics just gets incredibly complex out past 25,000 feet.
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Yeah.
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The drill pipe begins to undergo unpredictable helical buckling under the massive compression.
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Plus, the thermodynamic shifts in the drilling mud at those depths change the fluid's viscosity.
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Which alters the lubricity in ways the software can't accurately map.
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Aaron Powell Exactly.
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Operators literally have to throw out the textbook models.
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They rely entirely on their own empirical real-time data from the previous extreme wells just to predict if they can physically turn the drill pipe another hundred feet.
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Aaron Powell And because fighting that exponential friction is essentially a losing battle, it forces operators to make a brutal financial calculation when they inevitably get stuck.
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Which brings us to arguably the most jarring operational shift discussed in this entire round table.
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Right.
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What happens when a multimillion dollar drilling assembly gets stuck 30,000 feet underground?
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Well, the historical instinct in the oil field, the absolute mandate was to go get it.
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You do not leave a multimillion dollar tool and a thousand feet of untapped reservoir sitting in the dark.
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You initiate a fishing operation, you go pull it out.
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But fishing requires tripping the pipe.
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And as the round table pointed out, tripping 30,000 feet of pipe out of a hole isn't just an annoyance.
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It is a massive operational hazard.
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Yeah, tripping pipe at 10,000 feet is a standard procedure.
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Tripping a multi-mile drill string out to fix a tool and then pushing it all the way back in takes days of continuous rig time.
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And at 30,000 feet, you are dealing with incredible hydrostatic pressure from 15-pound drilling mud and extreme bottom hole temperatures.
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You can surface test an electronic tool and it works perfectly.
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But then you trip it 28,000 feet down a hole, vibrating the entire way down through a gauntlet of heat and pressure.
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The odds of the sensitive electronics inside that tool failing by the time it reaches the bottom again are terrifyingly high.
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Not to mention, the rotary steerable tools they use to navigate at the tip of the drill string cost around$1.3 million a piece.
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Even with the standard 50% insurance coverage, leaving one stuck at the bottom of the well is a massive financial blow.
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Wait, so if the tool is worth that much, are they seriously teaching their engineers to just abandon a million-dollar asset, abandon the remaining lateral, and walk away?
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That seems entirely counterintuitive for an industry obsessed with capital efficiency.
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If we connect this to the bigger picture, it actually represents a massive maturation in the industry's financial philosophy.
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It is the ultimate defeat of the sump cost fallacy.
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Explain the math behind that prioritization, because it's wild.
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So the new operator mandate discussed at the roundtable is prioritizing program economics over well economics.
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Imagine your directional tool fails at 33,000 feet on a planned 34,000 foot well.
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Okay, so you are a thousand feet short of your target.
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Right.
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If you stop the entire rig operation to fish that tool out or trip a new and in, you lose at least a week of continuous rig time.
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And that week of idle rig time completely cascades through your yearly schedule.
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Exactly.
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It delays the completions crew waiting to frack the well.
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It delays the production facilities waiting to process the oil.
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So that single week of waiting burns millions of dollars in delayed corporate cash flow across multiple departments.
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Yeah.
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One of the engineers made a comment detailing exactly how pragmatic this has become.
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He noted they are much more willing to abandon a stuck tool and walk away from a well in January than they are in December.
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Just simply because losing a week of schedule in January has 12 months to cascade and ruin the entire annual financial program for the whole company.
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Exactly.
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Whereas in December, the yearly targets are already largely baked in.
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It requires a ruthlessly detached approach to operations.
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Management has to train engineers to separate themselves emotionally from the loss of the hardware and look purely at the quarterly cash flow.
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Leaving a million dollars in the dirt stings, but halting a massive integrated manufacturing operation for a week damages the balance sheet infinitely more.
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They simply make the call, declare the well at 33,000 feet as total depth, cement it in, and move the rig to the next pad.
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But because abandoning a well is the ultimate last resort, the drilling teams are highly incentivized to get to total depth successfully.
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Right.
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But reaching total depth just hands the nightmare over to the next group.
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Oh, absolutely.
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Let's say you defeat the friction.
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You don't get stuck.
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You successfully drill a five-mile hole perfectly inside the window.
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You have a new, arguably, much harder problem.
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How do you actually frack a hole that long without blowing up your surface facilities?
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Oh, exactly.
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This is the supreme irony of the extended lateral era.
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The drilling engineers have mastered the physics of making long holes so effectively that they have accidentally created a crisis for the completions teams.
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The pumping technology and the chemical engineering simply have not caught up to the capabilities of the drill bit.
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To frack these wells, operators pump massive volumes of sand and water down the casing to prop open the microscopic fractures in the rock.
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But when the well is five miles long, it takes the sand eight to nine full minutes just to travel from the surface pumps to the toe of the well.
00:16:59.600 --> 00:17:07.680
And the chemicals they use to make the water slick enough to carry that sand, the friction reducers, or FR, were never designed for that kind of endurance.
00:17:08.000 --> 00:17:11.039
No, we have to look at the chemistry of why they fail.
00:17:11.279 --> 00:17:19.119
Friction reducers rely on long-chain polymer molecules to reduce the turbulence of the water, allowing it to carry heavy sand at high speeds.
00:17:19.440 --> 00:17:29.920
But over a nine-minute journey down a multi-mile pipe under immense sustained pressure, those polymer chains experience severe mechanical shear degradation.
00:17:30.240 --> 00:17:32.880
The physical turbulence literally tears the molecules apart.
00:17:33.200 --> 00:17:38.400
And when those polymer chains shear and fail, the fluid loses its carrying capacity.
00:17:38.559 --> 00:17:40.880
The sand drops out of the fluid mid-journey.
00:17:41.200 --> 00:17:43.759
Resulting in what the industry calls screening out.
00:17:43.920 --> 00:17:47.519
A screen out is when the sand completely packs off and clogs the well bore.
00:17:47.759 --> 00:17:50.000
And a screen out at 10,000 feet is a bad day.
00:17:50.160 --> 00:17:53.519
A screen out at 30,000 feet is a multimillion dollar catastrophe.
00:17:53.839 --> 00:18:02.079
Yeah, to clean out a multimile pipe clogged with packed sand, you have to bring in coiled tubing units, giant spools of continuous steel pipe to wash it out.
00:18:02.400 --> 00:18:09.599
But pushing coiled tubing 30,000 feet introduces the exact same exponential friction and helical buckling problems the drillers faced.
00:18:09.839 --> 00:18:18.880
It takes weeks, costs a fortune, and there is a very high probability you might never fully clean it out, effectively abandoning the bottom section of the mega well anyway.
00:18:19.200 --> 00:18:25.279
The operators literally cannot afford to have their completions teams screening out these massive investments.
00:18:25.519 --> 00:18:29.680
So how are they mitigating a chemical limitation they can't engineer their way out of yet?
00:18:30.000 --> 00:18:33.599
Well, the solution discussed at the roundtable isn't a new chemical additive.
00:18:33.759 --> 00:18:37.759
It is a complete shift in human psychology and on-site management.
00:18:38.160 --> 00:18:45.759
Because historically, the on-site representatives, the OSRs managing the frack job on the surface, were judged strictly by the design spreadsheets.
00:18:46.079 --> 00:18:51.680
Engineering wanted to see that every single pound of sand planned for that stage was pumped into the ground.
00:18:51.920 --> 00:18:54.480
If you left sand out, you failed the design.
00:18:54.880 --> 00:19:06.960
But now, because the financial penalty of a screen out is so devastating at these extreme depths, operators are explicitly retraining their OSRs to watch the surface pressure gauges over the spreadsheet.
00:19:07.200 --> 00:19:14.240
If they see a pressure spike indicating the sand is starting to pack off downhole, they are empowered to immediately hit the kill switch.
00:19:14.559 --> 00:19:17.039
The mandate from management is crystal clear.
00:19:17.200 --> 00:19:18.400
Do not pump the sweep.
00:19:18.559 --> 00:19:20.240
Do not try to force the sand through.
00:19:20.559 --> 00:19:26.559
Intentionally leave sand out of the hole, flush the well, call the stage complete, and move on to the next one.
00:19:26.880 --> 00:19:33.519
They are evaluating the OSRs now on their ability to prevent catastrophic interventions, not on perfect sand placement.
00:19:33.839 --> 00:19:39.680
And in tandem with that, they're also deliberately flooding the well with expensive friction reducer chemicals.
00:19:40.000 --> 00:19:45.759
Because the old operational mindset was always focused on saving pennies by optimizing chemical dosage.
00:19:46.160 --> 00:19:46.400
Right.
00:19:46.559 --> 00:19:52.079
But now the operators at the round table essentially stated they're overdosing the FR.
00:19:52.319 --> 00:19:57.680
The cost of excess chemicals is a rounding error compared to the cost of a catastrophic well intervention.
00:19:58.000 --> 00:20:03.119
This represents a massive strategic takeaway for any service companies supporting these operators.
00:20:03.359 --> 00:20:05.839
The value proposition has fundamentally shifted.
00:20:06.160 --> 00:20:09.440
Operators are no longer looking to save pennies on the budget option.
00:20:09.519 --> 00:20:14.160
They demand a 95 to 98% probability of operational success.
00:20:14.480 --> 00:20:20.319
Service companies need to design their entire product lines explicitly for 40,000 foot endurance.
00:20:20.559 --> 00:20:24.000
We see that specifically with downhole tools like bridge plugs, right?
00:20:24.160 --> 00:20:27.519
The plugs they use to isolate sections of the well during fracking.
00:20:27.839 --> 00:20:28.559
Precisely.
00:20:28.720 --> 00:20:36.960
Standard bridge plugs were not designed to withstand the cyclic pressure and extreme temperature variations of being said five miles deep for extended periods.
00:20:37.200 --> 00:20:43.119
When a bridge plug loses isolation during a frack job at those depths, the entire stage is compromised.
00:20:43.359 --> 00:20:54.240
If a service company can engineer a plug, a wireline cable, or a chemical suite that they can guarantee won't fail or shear apart at five miles deep, the operators will happily pay a premium for it.
00:20:54.400 --> 00:20:56.079
Failure is simply too expensive.
00:20:56.319 --> 00:21:05.440
It is genuinely incredible to see how a physical limitation downhole totally reshapes the corporate budgeting and management psychology happening in high-rises.
00:21:05.759 --> 00:21:13.200
We have covered the surface economics, the exponential friction, the defeat of the sunk cost fallacy, and the completions chemistry nightmare.
00:21:13.440 --> 00:21:17.119
As the roundtable wrapped up, the operators started looking toward the future.
00:21:17.440 --> 00:21:19.599
And the consensus was very clear.
00:21:19.920 --> 00:21:27.680
The era of chasing records, you know, drilling a 35,000-foot well just to get your company's name in a trade magazine is effectively over.
00:21:28.000 --> 00:21:30.960
The ego has completely drained out of the engineering.
00:21:31.119 --> 00:21:35.359
The new operational goal is seamless, boring repeatability.
00:21:35.680 --> 00:21:42.640
They want to drill a 24,000-foot well over and over again with zero drama and zero interventions.
00:21:42.960 --> 00:21:51.839
But interestingly, as they have mastered the subsurface environment to achieve that repeatability, they are now slamming into a totally different operational ceiling.
00:21:52.079 --> 00:21:54.079
And this one is located right back on the surface.
00:21:54.319 --> 00:21:56.000
Yeah, the surface facility bottlenecks.
00:21:56.240 --> 00:21:59.680
The production numbers the engineers were throwing around are almost difficult to.
00:22:00.240 --> 00:22:00.640
Comprehend.
00:22:01.039 --> 00:22:10.400
A massively successful extreme lateral can produce 7,000 barrels of oil or 200 million cubic feet of gas every single day from a single hole.
00:22:10.720 --> 00:22:14.480
Those volumes are staggering and they completely overwhelm standard surface infrastructure.
00:22:14.880 --> 00:22:23.119
You can drill the most mechanically perfect five-mile well in the basin, but if your surface processing facility can only handle half of what the well is capable of delivering.
00:22:23.440 --> 00:22:26.799
Or if your environmental error permits legally capped the volume, you can move them.
00:22:27.279 --> 00:22:27.440
Right.
00:22:27.519 --> 00:22:33.440
You have effectively built a massive five-lane highway that leads directly into a one-lane pole booth.
00:22:33.759 --> 00:22:39.759
The hydrocarbons literally have nowhere to go, forcing you to choke back the well and delay your return on investment.
00:22:40.079 --> 00:22:41.200
So what does this all mean?
00:22:41.519 --> 00:22:47.839
Well, we started this deep dive exploring the sheer audacity of steering a drill bit five miles horizontally.
00:22:48.079 --> 00:22:53.839
We unpacked how the high upfront costs of surface real estate drove the industry to push horizontally.
00:22:54.079 --> 00:23:00.480
We detailed how varying geology dictates the extreme physics of torque, drag, and exponential friction.
00:23:00.799 --> 00:23:09.920
And how those massive financial risks forced companies to rewrite their operational rulebooks, abandoning their own million-dollar tools to protect their broader schedules.
00:23:10.160 --> 00:23:15.519
The drillers pushed the physical limits, the completions teams are scrambling to keep their chemistry intact.
00:23:15.759 --> 00:23:20.240
And now, ironically, the massive success of the megawell has bottlenecked the surface.
00:23:20.559 --> 00:23:25.599
This raises an important question, and it highlights a fascinating paradigm shift for the broader energy sector.
00:23:25.920 --> 00:23:36.319
For the last 20 years, the most intense capital investment and innovation in this industry has been focused downward on the drill bit, the telemetry, the mud motors, and the subsurface mapping.
00:23:36.640 --> 00:23:45.440
But if drilling technology has now successfully outpaced the chemical engineering of fracking and completely outpaced the physical processing capacity of our surface penalties.
00:23:45.839 --> 00:23:49.200
Is the next great capital boom not going to happen underground at all?
00:23:49.519 --> 00:23:56.559
It seems highly likely the next multi-billion dollar frontier in energy efficiency is going to be entirely on the surface.
00:23:56.960 --> 00:24:06.160
We are looking at a massive pivot toward utilizing AI-driven facility management, edge computing, to optimize flow rates in real time.
00:24:06.559 --> 00:24:15.119
And advanced modular materials to instantly process, route, and manage the massive tidal wave of energy these megawells are unleashing.
00:24:15.440 --> 00:24:19.920
The drilling engineers have unequivocally proven they can find the reservoir and tap it from five miles away.
00:24:28.559 --> 00:24:46.960
The next time you were driving past an industrial park or an airport, consider the reality that somewhere beneath you, a team of engineers might be confidently steering a drill bit through solid rock, blindfolded, staying within a 10-foot window, all while managing the exact microeconomics of a multimillion dollar operation.
00:24:47.200 --> 00:24:49.359
It's an invisible world right under our feet.
00:24:49.599 --> 00:24:51.279
Thanks for joining us on this deep dive.
00:24:51.359 --> 00:24:52.799
We'll see you next time.